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Managed Pressure Drilling (MPD)Systems & Applications
Ken MuirVP, EngineeringKeep Drilling Pte. Ltd.
www.keepdrilling.com
Managed Pressure Drilling – WHY?• Conventional Drilling hasn’t changed much in over 100
years – it’s still an “Open to Atmosphere” system
• The easy drilling is behind us – drilling problems are increasing – and it’s getting worse
• Drilling performance curve is flat - technology advances are cancelled out by increased drilling problems
• Independent studies reveal that 25 – 33% of new wells can’t be drilled conventionally
• Drilling costs are now higher than facilities costs (used to be the other way round)
• MPD is a safer drilling method
• We need a better way to drill
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Drilling Methods
OVERBALANCED DRILLING: Drilling with BHP higher than formation pressure = CONVENTIONAL DRILLING.Objective: To minimise the chance of an influx.
PERFORMANCE DRILLING: Drilling with low BHP to enhance ROP & bit life. Used in well construction = AIR or GAS DRILLING. Objective: To enhance penetration rate
UNDERBALANCED DRILLING: Drilling with the BHP below reservoir pressure – naturally lower or induced = UBD.Objective: To minimise reservoir damage
MANAGED PRESSURE DRILLING: Drilling with precisely controlled BHP to avoid influx, fluid loss or borehole instability. Pressure profile managed by addition of surface pressure or by change in hydrostatics or friction pressure.Objective: To minimise pressure related drilling problems
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MPD Advantage
Conventional Drilling:BHP = MW + Annulus Friction Pressure
BHP control = only pump speed & MW change, because it’s an “Open to Atmosphere” System.
Managed Pressure Drilling (MPD):BHP = MW + Annulus Friction Pressure + BackpressureBHP control = pump speed change, MW change &
application of back-pressure, because it’s an “Enclosed, Pressurized System”.
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IADC Definition:
•“The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly”
•MPD does not change the downhole pressure window – pore pressure and fracture gradient remain unchanged
•but MPD helps us to remain in the “window”
MPD Advantage
Source James K Dodson Company StudyDirectional & Completion
5%
Chemical Problems3%
Stuck Pipe11%
Sloughing Shale3%
Wellbore Instability1%
Cement squeeze9%
Twist Off3%
Wait on Weather13%
Casing or WellheadFailure
5%
Rig Failure21%
Other1% Kick
9% Gas Flow <0%
Shallow Water Flow3%
Lost Circulation13%
MPD can reduce NPT in 43% of problems
Problem Incidents – GoM Gas Wells
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Who is using MPD?
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MPD System Components
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Conventional BOP & Choke Manifold (no change)
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Automated MPD System
Step Choke Pressure
(psi)
Pump Rate
(gpm)
Pump (spm)
Pump Press(psi)
Friction DP (psi)
BHP(psi)
Pump Rate while drilling 20 196 70 2995 393 1566Increase choke pressure 48 197 70 3003 393 1617Decrease pump rate 48 183 65 2646 345 1566Increase choke pressure 113 183 65 2691 345 1611Decrease pump rate 113 170 60 2395 300 1566Increase chore pressure 155 170 60 2397 258 1608Decrease pump rate 155 155 55 2081 258 1566
And continue with steps until pumps are stoppedDecrease pump rate 323 85 30 990 90 1566Increase chore pressure 347 85 30 1014 90 1590Decrease pump rate 347 71 25 931 66 1566Increase choke pressure 359 71 25 843 66 1578Decrease pump rate 359 45 16 596 54 1566Increase chore pressure 413 45 16 650 54 1620Decrease pump rate 413 0 0 413 0 1566
Make a connection and keep BHP within a 50psi window
50psi range
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Manual CBHP System
Types of MPD
• Returns Flow Control (Enclosed wellbore vs. open-to-atmosphere)
• Pressurized or Floating Mud Cap Drilling (PMCD)• Constant Bottom Hole Pressure (CBHP)
• Dual gradient (DG)
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MPD allows the BHP to be adjusted to penetrate the “Windows” between Pore
Pressure & Fracture Pressure
Pore Pressure
Fracture Pressure
MW MW + ECD
Pore – Fracture Pressure Window
Easy to drill wells in a large “Drilling Window”
Collapse Pressure Pore
Pressure
Fracture Pressure
Overburden Pressure
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Narrow “Drilling Windows” are not easy to drill
Pore – Fracture Pressure Window
Collapse Pressure
Pore Pressure
Fracture Pressure
Overburden Pressure
Narrow Drilling Window
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Constant Bottom Hole Pressure – CBHP Bo
ttom
Hol
e Ci
rcul
atin
g Pr
essu
re
Time
Fracture Pressure
Reservoir Pressure
Fluid Losses Fluid Losses
Bottom Hole Pressure
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Constant Bottom Hole Pressure – CBHPBo
ttom
Hol
e Ci
rcul
atin
g Pr
essu
re
Time
Fracture Pressure
Reservoir Pressure
Bottom Hole Pressure
Kick Kick
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Tool Joints
Automated MPD System – Reaming to Bottom
Automated MPD System
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Kick Tolerance is greatly reduced
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Automated MPD System
409 psi = 73 gpm of mud loss
339 psi = 5 gpm of mud loss
Accurate determination of the fracture gradient
Low Pressure RCD
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Low pressure RCD with spare seal elements and components for pressure testing and logging.
Pressure Rating:Rotating and/or Stripping:500psiStatic: 1,000psi
Over 600 wells are drilled with Rotating Control Devices (RCD) every day in the US & Canada
High Pressure RCD
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Pressure Rating:Rotating and/or Stripping:2,500psiStatic: 5,000psi
PMCD System – Floating Rig
4” Annulus Injection Line from Mud Pump
6” HCR
4” Bleed-off Line to Choke Manifold
2” Fill-up Line from Trip Tank Pump
4” HCR
4” HCR
Riser tensioner lines support the full riser
weight and PMCD equipment
Rotating Control Device
6” Line Flow Line
Riser Slip Joint used in the collapsed position
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PMCD System – Floating Rigs
Semi-submersible Drillship
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MPD has already been performed on Drillships, Semi-subs, Jack-ups & Platform Rigs
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Automated MPD – Floating Rig
• Full Automated MPD System for floating rig applications in harsh environment conditions
• Project due to commence July 2008
MPD Applications
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• Kick Control (Influx Control)• Severe Drilling Fluid Loss – Fractured or
Vugular Formation• Differential Sticking – Stuck Pipe – Twist-off• Tight Pore Pressure – Fracture Pressure
“Windows”• Depleted Reservoir Drilling• HPHT Drilling• Unknown Pore Pressure
MPD Applications contd.
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• Unstable Wellbore (Wellbore Instability) • MPD + ERD (Extended Reach Drilling) • Low ROP• Drilled Gas (Nuisance Gas) • High H2S Levels• High ECD • Ballooning / Breathing formation
KICK CONTROL – Advantages of MPD
Safety • Response and influx size reduced using an enclosed system• Enclosed wellbore is safer than “open to atmosphere” system
because back-pressure can be applied immediately• The majority of kicks are low pressure events that can easily
be handled by an RCD• Lower risk of exceeding MAASP with MPD (because of the
smaller influx) and consequently lower risk of breaking down the casing shoe
• Lower risk of taking second influx with MPD (longer critical choke control needed while circulating out the larger influx)
Time & Cost
• The drillstring can be moved all the time, reducing the risk of differential sticking – potential huge cost saving
• One full circulation at slow circulating rate can take hours, plus time to weight up the kill mud. Typically 12 – 24 hours can be saved (the time loss varies – GOM deepwater – the average time loss due to taking a kick is 10 days)
• Reduces wear & tear on BOP and rig choke system
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PMCD – Advantages & DisadvantagesAdvantages • Permits safe and efficient drilling through severe or total
loss zones – highly cost effective compared to conventional drilling
• Well can be drilled to TD with virtually no loss of rig time – no major AFE Overruns
• Limits damage to the reservoir caused by LCM, gunk and cement
• Very good technique for H2S environments because the gas is pushed back into formation – no gas to surface
Disadvantages • There are no returns to surface – Geologists don’t like this technique – no samples
• At TD, or for intermediate trips, there still remains the issue of how to get out of the hole with total losses –casing valve or pumping technique
• PMCD uses large volumes of fluid – a week of drilling could require 120 – 150,000bbls of fluid including drillpipe & annulus injection
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Case History•Ran 7” casing “tie-back” string to
top of liner hanger with casing valve to allow drillstring recovery
•Changed to PMCD•Injected water in annulus with
high surface pressure on RCD (1,400psi)
•Drilled out tie-back shoe, gunk plug plus 3m of new formation. POOH closing casing valve to isolate reservoir pressure
•Reservoir section drilled in two further trips
• SPP range 1,900 – 2,100psi• CP range 1,250 – 1,400psi• ROP ~ 4 – 5 metres/hour
7” Tie-back casing string
Casing Valve
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MPD + ERDPROBLEM: Compare two wells of 3,500mMD. A vertical well with APL of 478psi and 10.6ppg ECD using 9.8ppg mud, and an ERD well with TVD of 2,000m. The ERD well would have the same APL but an ECD of 11.2ppg.X Greatly increased ECDX At reduced depth –
weaker formation
MPD SOLUTION: Drill with 9.3ppg mud giving a 10.6ppg ECD and trap annulus pressure during connections to control any influx or maintain wellbore stability
ECD (ppg) = Annular Pressure Loss (psi) / 0.052 / TVD (ft) + Current Mud Density (ppg)
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High ECDPROBLEM:• While drilling a 6-1/8” hole at 3,064mTVD with 13.2ppg mud and
an APL of 575psi, ECD is so high that losses are being caused. The pump rate must be reduced and ROP controlled to avoid hole cleaning problems and stuck pipe
• Circulating BHP adds 1.1 – 1.6ppg, so ECD = 14.3 – 14.8ppg
Pore Pressure
FracturePressure
MW MW + ECDMPD SOLUTION:• Drill with a light fluid. Can be
statically balanced but with the MPD system for additional security
• Eliminate the 0.5ppg drilling margin – enclosed wellbore
• Or go statically underbalanced with a 12.1ppg MW and trap 575psi in the annulus on the choke during connections (ECD = 13.2ppg)
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Ballooning / Breathing FormationPROBLEM:• The formation charges up with fluid and pressure while drilling
and releases this fluid pressure back into the wellbore when the pumps are shut down
• The drilling supervisor thinks the well is flowing and orders the mud weight increased – which increases the BHP – which charges up the formation even more – so it flows even more at the next connection
MPD SOLUTION:• If the well is flowing due to an influx – the flow trend will be
gradually increasing – but if the problem is ballooning formation then the flow trend will be decreasing
• An Automated MPD System, with highly accurate flow measurement can clearly identify what is happening.
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Ballooning Formation – decreasing trend
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Ballooning Formation
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Ballooning Formation – a Clear Picture
Kick Tolerance• Kick Tolerance = the volume of gas that can safely be shut-in and
circulated out without breaking down the last casing shoe
• Company policy states kick tolerance limits – and management approval is required for low kick tolerance volumes (<25bbls?)
• Enclosed wellbore systems automatically resist the tendency for the flow to increase. An influx automatically causes an increase in back-pressure. (Not the case for “Open to Atmosphere” systems)
• An automated MPD system detects the flow instantly and automatically applies back-pressure, stopping an influx and matching inflow to outflow very quickly
• As the use of MPD becomes “normal practice”, Drilling Engineers will design wells with deeper casing seats – even removing intermediate casing strings. Why design for a 25bbl kick when MPD reduces the influx to less than 10% of this figure?
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MPD - Conclusions
• MPD forces Drilling Engineers & Supervisors to change their ideas – there is a better way.
• Conventional methods are often used well past the time that economics dictate a new approach is required – often wasting US$ millions on a well.
• Enclosed wellbore solutions are inherently safer and more efficient than conventional “Open to Atmosphere” systems - a well in “MPD Mode” is a well in “Safe Mode”).
• Many examples exist where MPD delivered a well when conventional methods failed – in fact this is the target market for MPD
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